Cross-linkers for hydraulic fracturing fluid

ABSTRACT

A method of forming a wellbore fluid, the method including introducing a hydratable polymer and introducing a crosslinker comprised of at least a silica material, the crosslinker having a dimension of from about 5 nm to about 100 nm.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional PatentApplication No. 61/450,684, filed Mar. 9, 2011, the disclosure of whichis incorporated by reference herein in its entirety.

TECHNICAL FIELD

This present disclosure relates generally to the field of crosslinkersfor oilfield application, and relates more particularly, but not by wayof limitation, to methods of using crosslinkers in various oilfieldapplications.

BACKGROUND

To enhance or increase the production of oil and gas hydrocarbons fromwells bored into subterranean-formations, it has been common practice topump a viscous fluid at high pressures down into the wellbore to crackthe formation and force the fracturing fluid into those cracks. Thefracturing fluid is also used to carry sand or other types of particles,called proppants, to hold the cracks open when the pressure is relieved.The cracks held open by the proppant provide additional paths for theoil or natural gas to reach the wellbore, which, in turn, increases theproduction of oil and/or natural gas from the well.

In order to form the viscous fluid, a thickening agent (or aviscosifying agent), such as a polymer, is incorporated into water or anaqueous solution. A number of polymers are known for this purposeincluding a number of polysaccharides. Viscosity can then be increasedconsiderably, giving a viscoelastic gel, by cross-linking the polymermolecules. This has particular application in connection with theextraction of hydrocarbons such as oil and natural gas from a reservoirwhich is a subterranean geologic formation by means of a drilled wellthat penetrates the hydrocarbon-bearing reservoir formation. In thisfield, one commercially very significant application of thickened fluidsis for hydraulic fracturing of a subterranean formation. The polymericthickening agent may (1) assist in controlling leak-off of the fluidinto the formation, (2) aid in the transfer of hydraulic fracturingpressure to the rock surfaces and (3) facilitate the suspension andtransfer into the formation of proppant materials that remain in thefracture and thereby hold the fracture open when the hydraulic pressureis released.

Further applications of thickened fluids in connection with hydrocarbonextraction may include acidizing, control of fluid loss, diversion,zonal isolation, and the placing of gravel packs. Gravel packing is aprocess of placing a volume of particulate material, frequently coarsesand, within the wellbore and possibly extending slightly into thesurrounding formation. The particulate material used to form a gravelpack may be transported into place in suspension in a thickened fluid.When it is in place, the gravel pack acts as a filter for fine particlesso that they are not entrained in the produced fluid.

Crosslinking of the polymeric materials then serves to increase theviscosity and proppant carrying ability of the fluid, as well as toincrease its high temperature stability. Typical crosslinking agentscomprise soluble boron, zirconium, and titanium compounds. Chromium andaluminum compounds have also been used. The viscosity of solutions ofguar gum and similar thickeners can be greatly enhanced by crosslinkingthem with boric acid or other boron containing materials. Thus, boroncrosslinked guar gum solutions are useful as fracturing fluids.

Historically, as described in U.S. Pat. Nos. 6,310,104 and 6,372,805,the disclosures of which are incorporated by reference herein in theirentirety, amorphous borosilicate particles in the size domain of 10-20nm and in the concentration range of 20-40 wt % in water solvent havebeen used in the paper industry. The mono-dispersion is achieved byadding aqueous silicic acid to an aqueous boric oxide solution withextended agitation, followed by recovering the aqueous colloidscontaining amorphous, not glassy, borosilicate nano-spheres. Theseproducts have been used in paper industry to increase the conversion oftrees to paper by insuring that raw material fibers used in the processare retained and become part of the final paper sheet. They alsofacilitate the capture of raw material fibers in the produced papersheet and minimize the loss of value resources to the generation ofwaste. In addition, they enhance the removal of water from municipalsludges which reduces fuel consumption during transportation of thesludges. However, neither of the above references described thatamorphous borosilicate may be used a crosslinker for a wellborecomposition used to treat a subterranean formation.

The viscosity of these crosslinked gels can be reduced by mechanicalshearing (i.e., they are shear thinning) but gels cross-linked withboron compounds may reform spontaneously after exposure to high shear.This property of being reversible makes boron-crosslinked gelsparticularly attractive and they have been widely used. Furthermore, theoverall performance of a fracturing fluid intimately depends on thecross-linking chemistry that forms the viscous gel. Borate crosslinkedgel fracturing fluid typically utilize the borate anion to crosslink thehydrated polysaccharide polymers and thus provide increased viscosity.The crosslinked polymer may then be rendered chemically reversible byaltering the pH of the fluid system. It is this reversiblecharacteristic of crosslinked borate polymer fluids that may improve theeffectiveness of the subsequent clean up step more effectively, and thuspotentially result in good regained permeability and conductivity.

It is generally desirable to achieve the desired viscosity with a lowconcentration of thickening materials so as to reduce cost of materialsand reduce the amount of material which is delivered below ground andmay need to be removed in a subsequent cleanup operation. Also, boronand metals, in sufficient concentration, can be toxic to the environmentand so it is also desirable to minimize the amount of boron or metalliccross-linking agent which is used.

Additionally, it is desirable to develop a new cross-linker materialthat is completely free of boron or, alternatively, to use an insolubleform of boron with an identical electronic configuration of borax sothat the well established boron crosslink chemistry can remain intact.

SUMMARY OF THE DISCLOSURE

There is a need, addressed by the subject matter described herein, for awellbore composition and a method of forming and/or applying a wellborecomposition, to resolves the above issues.

The above and other issues are addressed by the present application,wherein in embodiments, the application relates to a method of forming awellbore fluid, the method comprising: introducing a hydratable polymer;and introducing a crosslinker comprised of at least a silica material,the crosslinker having a dimension of from about 5 nm to about 100 nm.

In embodiments, described herein is a method of treatment of a wellboreor a subterranean formation penetrated by a wellbore, the methodcomprising: introducing a wellbore composition to the wellbore or thesubterranean formation, the wellbore composition comprised of at least ahydratable polymer and a crosslinker, wherein the crosslinker iscomprised of at least a silica material, the crosslinker having adimension of from about 5 nm to about 100 nm.

BRIEF DESCRIPTIONS OF DRAWINGS

FIG. 1 represents the rheological profile for Example 1 comprised of a 5ppm borosilicate colloidal dispersion crosslinked with 30 lbm/1,000 galUS guar at 130° F. at a constant pressure of 200 psia and at a shearrate 100/s (pH 9.1).

FIG. 2 represents the rheological profile for Example 2 comprised of a12.4 ppm borosilicate colloidal dispersion crosslinked with 30 lbm/1,000gal US guar at 120° F. at multiple pressure rampings between ambient and20,000 psia and at a shear rate 100/s (pH 9.4).

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation—specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. In addition, the compositionused/disclosed herein can also comprise some components other than thosecited. In the summary of the application and this detailed description,each numerical value should be read once as modified by the term “about”(unless already expressly so modified), and then read again as not somodified unless otherwise indicated in context. Also, in the summary ofthe invention and this detailed description, it should be understoodthat a concentration range listed or described as being useful,suitable, or the like, is intended that any and every concentrationwithin the range, including the end points, is to be considered ashaving been stated. For example, “a range of from 1 to 10” is to be readas indicating each and every possible number along the continuum betweenabout 1 and about 10. Thus, even if specific data points within therange, or even no data points within the range, are explicitlyidentified or refer to only a few specific, it is to be understood thatinventors appreciate and understand that any and all data points withinthe range are to be considered to have been specified, and thatinventors possessed knowledge of the entire range and all points withinthe range.

As used in the specification and claims, “near” is inclusive of “at.”

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description.

The term “treatment”, or “treating”, refers to any subterraneanoperation that uses a fluid in conjunction with a desired functionand/or for a desired purpose. The term “treatment”, or “treating”, doesnot imply any particular action by the fluid.

The term “fracturing” refers to the process and methods of breaking downa geological formation and creating a fracture, i.e., the rock formationaround a wellbore, by pumping fluid at very high pressures (pressureabove the determined closure pressure of the formation), in order toincrease production rates from or injection rates into a hydrocarbonreservoir. The fracturing methods otherwise use conventional techniquesknown in the art.

A “crosslinker” or “crosslinking agent” is a compound mixed with abase-gel fluid to create a viscous gel. Under proper conditions, thecrosslinker reacts with a multiple-strand polymer to couple themolecules, creating a crosslinked polymer fluid of high, but closelycontrolled, viscosity.

The term “hydraulic fracturing” as used in the present applicationrefers to a technique that involves pumping fluids into a well atpressures and flow rates high enough to split the rock and createopposing cracks extending up to 300 m (1000 feet) or more from eitherside of the borehole. Later, sand or ceramic particulates, called“proppant,” are carried by the fluid to pack the fracture, keeping itopen once pumping stops and pressures decline.

As used herein, the new numbering scheme for the Periodic Table Groupsare used as in Chemical and Engineering News, 63(5), 27 (1985).

As used herein, the term “liquid composition” or “liquid medium” refersto a material which is liquid under the conditions of use. For example,a liquid medium may refer to water, and/or an organic solvent which isabove the freezing point and below the boiling point of the material ata particular pressure. A liquid medium may also refer to a supercriticalfluid.

As used herein, the term “polymer” or “oligomer” is used interchangeablyunless otherwise specified, and both refer to homopolymers, copolymers,interpolymers, terpolymers, and the like. Likewise, a copolymer mayrefer to a polymer comprising at least two monomers, optionally withother monomers. When a polymer is referred to as comprising a monomer,the monomer is present in the polymer in the polymerized form of themonomer or in the derivative form of the monomer. However, for ease ofreference the phrase comprising the (respective) monomer or the like isused as shorthand.

The terminology and phraseology used herein is solely used fordescriptive purposes and should not be construed as limiting in scope.Language such as “including,” “comprising,” “having,” “containing,” or“involving,” and variations thereof, is intended to be broad andencompass the subject matter listed thereafter, equivalents, andadditional subject matter not recited.

Described herein is a method of well treatment, that includes a methodof forming a wellbore fluid, the method comprising: introducing ahydratable polymer; and introducing a crosslinker comprised of at leasta silica material, the crosslinker having a dimension of from about 5 nmto about 100 nm.

Polymer

In certain embodiments of the present application, the well treatmentfluid comprises at least one polymer (also referred to as a“viscosifier”) and at least one crosslinker, the polymer and crosslinkerreacting under proper conditions to form a crosslinked polymer. Thepolymer should not prematurely crosslink before the desired set time.The polymer may be a hydratable polymer, such as a polysaccharide.

The hydratable polymer may be a high molecular weight water-solublepolysaccharide containing cis-hydroxyl groups that can complex thecrosslinking agent. Without limitation, suitable polysaccharides includethose polysaccharides having a molecular weight in the range of about200,000 to about 3,000,000 Daltons, such as, for example, from about500,000 to about 2,500,000 Daltons and from about 1,500,000 and2,500,000 Daltons.

Polysaccharides having adjacent cis-hydroxyl groups for the purposes ofthe present application include such polysaccharides as thegalactomannans. The term galactomannans refers in various aspects tonatural occurring polysaccharides derived from various endosperms ofseeds. They are primarily composed of D-mannose and D-galactose units.They generally have similar physical properties, such as being solublein water to form thick, highly viscous solutions which usually can begelled (crosslinked) by the addition of such inorganic salts as borax.Examples of some plants producing seeds containing galactomannan gumsinclude Tara, Huizache, locust bean, Pola verde, Flame tree, guar beanplant, Honey locust, Lucerne, Kentucky coffee bean, Japanese pagodatree, Indigo, Jenna, Rattlehox, Clover, Fenergruk seeds and soy beanhulls. The gum is provided in a convenient particulate form, whereinexamples of polysaccharide include guar and its derivatives. Theseinclude guar gum, carboxymethylguar, hydroxyethylguar,carboxymethylhydroxyethylguar, hydroxypropylguar (HPG),carboxymethylhydroxypropylguar, and combinations thereof. As agalactomannan, guar gum is a branched copolymer containing a mannosebackbone with galactose branches.

Upon hydrolysis, galactomannans may yield the two simple sugars,mannose, and galactose. Analyses have indicated that suchpolysaccharides are long chain polymers of D-mannopyranose units linkedat the β-1,4 position which have D-galactopyranose units located as sidechains on the molecule. The D-galactopyranose units are connected to theC₆ atoms of the D-mannose units that make up the main structuralframework. The ratio of D-galactose to D-mannose in the galactomannansgenerally varies from about 1:1.2 to about 1:2, depending upon theparticular vegetable source from which the material is derived. In allcases, however, the mannose residues have cis-hydroxyl groups at the C₂and C₃ positions, accounting for the crosslinking reactions obtainedwith the galactomannans and making them useful for the purposes of thepresent application.

As discussed above, some nonlimiting examples of suitable polymersinclude guar gums, high-molecular weight polysaccharides composed ofmannose and galactose sugars, or guar derivatives such as hydropropylguar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropylguar (CMHPG). Cellulose derivatives such as hydroxyethylcellulose (HEC)or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose(CMHEC) may also be used, and have been shown to be useful asviscosifying agents as well. Biopolymers such as xanthan, diutan, whelangum and scleroglucan may also be used. Synthetic polymers such aspolyacrylamide and polyacrylate polymers and copolymers, as well asdiutans, may be useful for high-temperature applications. Additionalexamples of suitable polymers are described in U.S. Pat. No. 5,981,446,U.S. Pat. No. 7,497,263 and U.S. Pat. No. 7,968,501, the disclosures ofwhich are incorporated by reference herein in their entirety.

The polymer may be present in the wellbore fluid in an amount of fromabout 0.05 weight percent to about 10 weight percent, from about 0.1weight percent to about 5 weight percent, from about 0.1 weight percentto about 2 weight percent and from about 0.1 weight percent to about 0.5weight percent, based upon the total weight of the wellbore fluid.

Crosslinker

The wellbore fluid described herein may also include a crosslinker. Asdiscussed above, fracturing fluid must be chemically stable andsufficiently viscous to suspend the proppant while it is sheared andheated in surface equipment, well tubulars, perforations and thefracture; otherwise, premature settling of the proppant occurs,jeopardizing the treatment. Crosslinkers join polymer chains for greaterthickening.

The overall performance of a fracturing fluid intimately depends on thecross-linking chemistry that forms the viscous gel. Borate crosslinkedgel fracturing fluid utilizes borate anion to crosslink the hydratedpolysaccharide polymers and provide increased viscosity. The crosslinkobtained by using borate is chemically reversible as triggered byaltering the pH of the fluid system. The reversible characteristic ofthe crosslink in borate fluids helps subsequent clean up step moreeffectively, resulting in good retained permeability and conductivity.

It is desirable to use an insoluble form of boron with an identicalelectronic configuration of borax so that the well established boroncrosslink chemistry can remain intact, together with the vastengineering procedures related to its application in stimulationindustry.

When the crosslinker contain boron, the concentration of boron in thefluid may be in a range of from 0.5 ppm to 700 ppm elemental boron, fromabout 1.0 ppm to about 500 ppm, from about 5.0 ppm to about 250 ppm,from about 10 ppm to about 100 ppm, from about 15 ppm to about 75 ppmand from about 15 ppm to about 50 ppm. This also means that theproportion of boron to the polymer to be crosslinked may be low. Thusthe amounts of the polymer and boron in the fluid may be such that theamount of boron is not more than 0.002 or 0.001 times the amount of thepolymer. Expressing this in terms of concentrations, the content ofboron may be not more than 2 ppm, possibly not more than 1 ppm for eachgram of polymer in 1 liter of solution. For a solution containing 4gm/liter of polymer to be crosslinked this would be no more than 8 ppm,possibly not more than 4 ppm boron in the solution. The quantity ofcross linking agent may be no more than 30%, possibly no more than 20,15 or 10% by weight of the polymer to be crosslinked.

In embodiments, the crosslinker includes at least silica and has adimension of from about 5 nm to about 100 nm. In other embodiments, thecrosslinker may have a dimension of from 10 nm to about 75 nm, fromabout 20 nm to about 60 nm, from about 25 nm to about 50 nm and fromabout 30 nm to about 40 nm. The cross-linking agents and any of thesupporting structures within them may have at least one dimension whichis at least 5 nanometer (5 nm). Whilst they may or may not have aspherical shape or a cylindrical shape, they may have a particle size,which is expressed as the diameter of an equivalent sphere, of at least5 nm, possibly at least 10, 20 or 25 nm.

The crosslinker may also include a non-aqueous solvated crosslinker,such as borosilicate. Borosilicate is a material having a mole ratio ofboron to silicon ranging from about 1:100 to about 2:5 and/or a moleratio of sodium to silicon ranging from about 6:1000 to 1.04:1. Thecrosslinker may also be a colloid of borosilicate having a chemistrysimilar to that of borosilicate glass, such as, for example, an aqueouscolloid. This colloid may be generally prepared by reacting an alkalimetal salt of a boron containing compound with silicic acid underconditions resulting in the formation of a colloid. The surface area ofthe borosilicate should be in the range of from about 15 to about 3000m²/g, from about 50 to about 3000 m²/g, from about 250 to 3000 m²/g andfrom about 700 to 3000 m²/g.

As described in U.S. Pat. No. 6,310,104, the disclosure of which isincorporated by reference herein in its entirety, colloidal borosilicatematerials may be prepared by first preparing silicic acid. This may beadvantageously accomplished by contacting an alkali metal silicatesolution, such as a dilute solution of the alkali metal silicate with acommercial cation exchange resin, such as a so called strong acid resin,in the hydrogen form and recovering a dilute solution of silicic acid.The silicic acid may then be added, with agitation to a dilute solutionof an alkali metal borate at a pH of from 6-14, and a colloidalborosilicate product suspended in water is recovered. Alternatively, thealkali metal borate and the silicic acid may be added simultaneously toprepare suitable materials. The concentration of the silicic acidsolution utilized is generally from 3 to 8 percent by weight SiO₂, andfrom about 5 to about 7 percent by weight SiO₂. The weight percent ofthe borate solution utilized is generally 0.01 to 30 and from 0.4 to 20weight percent as B₂O₃. The borate salt utilized may range over a widevariety of compounds, wherein examples of the borate salt includecommercial borax, sodium tetraborate decahydrate, or sodium tetraboratepentahydrate. Other water soluble borate materials may be utilized. Thepreparation of the colloidal borosilicate material of this applicationmay be accomplished with or without pH adjustment as it is sometimesadvisable to conduct the reaction at a pH of 7.5 to 10.5 or of 8 to 9.5through the addition of an appropriate alkali metal hydroxide, such assodium hydroxide, to the reaction mixture. Other methods of preparingthe colloidal borosilicates of this application may also be utilized.These methods could encompass preparing the colloidal borosilicate asabove and spray drying the particles followed by grinding, or othermethods which would yield a borosilicate material meeting the parametersset forth above.

Embodiments of the borosilicate include, among others, silicon dioxide(SiO₂), boric oxide (B₂O₃), aluminum oxide (Al₂O₃), and at least onealkali oxide. The alkali oxide in the borosilicate may include lithiumoxide (Li₂O), potassium oxide (K₂O), and sodium oxide (Na₂O). Notintending to be bound by theory, the Al₂O₃ may play a role in inhibitingthe formation of cristobalite and tridymite crystals during thesintering of the borosilicate glass composition. In addition, the B₂O₃may increase the meltability of the borosilicate and potentially act asan efficient flux without significantly increasing the coefficient ofthermal expansion (CTE) of the borosilicate glass, while the alkalioxide may increase the CTE of the borosilicate glass. The borosilicatecolloidal particles may have the ability to crosslink guar (and otherpolysaccharide polymers) effectively since its great population ofsurface accessible boron atoms retains essentially identical electronicconfiguration to tetrahedral borate anion which, in an appropriate pHdomain, enables the formation of complex associations with the abundantcis-hydroxyl groups in sugar residues.

The crosslinker may further include one or more transition metals, suchas zirconium, titanium and aluminum. One or more of the abovecrosslinkers may be included in the wellbore composition such that a“combination” of these materials is included in the wellborecomposition. In some embodiments, the silica has a concentration of20-50 wt % in the crosslinker.

Furthermore, in certain instances, a delay in crosslinking may beadvantageous. For example, a delayed crosslinker can be placed downholeprior to crosslinking; the gel fluid is prepared on the surface, thencrosslinks after being introduced into a wellbore which penetrates asubterranean formation, forming a high viscosity treating fluid therein.The delay in crosslinking is beneficial in that the amount of energyrequired to pump the fluids can be reduced, the penetration of certainfluids can be improved, and shear and friction damage to polymers can bereduced. By delaying crosslinking, crosslinkers can be more thoroughlymixed with the polymer fluid prior to crosslink initiation, providingmore effective crosslinks, more uniform distribution of crosslinks, andbetter gel properties.

Additional Materials

The wellbore fluid of the present application may also includeadditional constituents or material. One additional material that may beincluded is a breaker. The purpose of this material is to “break” ordiminish the viscosity of the crosslinked fluid so that this fluid ismore easily recovered from the formation during cleanup. The breakerdegrades the crosslinked polymer to reduce its molecular weight. If thepolymer is a polysaccharide, the breaker may be a peroxide withoxygen-oxygen single bonds in the molecular structure. These peroxidebreakers may be hydrogen peroxide or other material such as a metalperoxide that provides peroxide or hydrogen peroxide for reaction insolution. A peroxide breaker may be a so-called stabilized peroxidebreaker in which hydrogen peroxide is bound or inhibited by anothercompound or molecule(s) prior to its addition to water but is releasedinto solution when added to water.

Examples of suitable stabilized peroxide breakers include the adducts ofhydrogen peroxide with other molecules, and may include carbamideperoxide or urea peroxide (CH₄N₂O.H₂O₂), percarbonates, such as sodiumpercarbonate (2Na₂CO₃.3H₂O₂), potassium percarbonate and ammoniumpercarbonate. The stabilized peroxide breakers may also include thosecompounds that undergo hydrolysis in water to release hydrogen peroxide,such sodium perborate. A stabilized peroxide breaker may be anencapsulated peroxide. The encapsulation material may be a polymer thatcan degrade over a period of time to release the breaker and may bechosen depending on the release rate desired. Degradation of the polymercan occur, for example, by hydrolysis, solvolysis, melting, or othermechanisms. The polymers may be selected from homopolymers andcopolymers of glycolate and lactate, polycarbonates, polyanhydrides,polyorthoesters, and polyphosphacenes. The encapsulated peroxides may beencapsulated hydrogen peroxide, encapsulated metal peroxides, such assodium peroxide, calcium peroxide, zinc peroxide, etc. or any of theperoxides described herein that are encapsulated in an appropriatematerial to inhibit or reduce reaction of the peroxide prior to itsaddition to water.

The peroxide breaker, stabilized or unstabilized, is used in an amountsufficient to break the heteropolysaccharide polymer or diutan. This maydepend upon the amount of heteropolysaccharide used and the conditionsof the treatment. Lower temperatures may require greater amounts of thebreaker. In many, if not most applications, the peroxide breaker may beused in an amount of from about 0.001% to about 20% by weight of thetreatment fluid, more particularly from about 0.005% to about 5% byweight of the treatment fluid, and more particularly from about 0.01% toabout 2% by weight of the treatment fluid. The peroxide breaker may beeffective in the presence of mineral oil or other hydrocarbon carrierfluids or other commonly used chemicals when such fluids are used withthe heteropolysaccharide.

The breaker may also be encapsulated or in an enclosure to the delay therelease of the breaker, such as those disclosed in U.S. Pat. No.4,741,401 (Walles, et. al), hereinafter incorporated by reference in itsentirety. Additional examples of breakers include: ammonium, sodium orpotassium persulfate; sodium peroxide; sodium chlorite; sodium, lithiumor calcium hypochlorite; bromates; perborates; permanganates;chlorinated lime; potassium perphosphate; magnesium monoperoxyphthalatehexahydrate; and a number of organic chlorine derivatives such asN,N′-dichlorodimethylhydantoin and N-chlorocyanuric acid and/or saltsthereof. The specific breaker employed may depend on the temperature towhich polymer gel is subjected. At temperatures ranging from about 50°C. to about 95° C., an inorganic breaker or oxidizing agent, such as,for example, KBrO₃, and other similar materials, such as KClO₃, KlO₃,perborates, persulfates, permanganates (for example, ammoniumpersulfate, sodium persulfate, and potassium persulfate) and the like,are used to control degradation of the polymer gel. At about 90 to 95°C. and above, typical breakers include suitable breaker, an example ofwhich is sodium bromate.

Breaking aids or catalysts may be used with the peroxide breaker. Thebreaker aid may be an iron-containing breaking aid that acts as acatalyst. The iron catalyst is a ferrous iron (II) compound. Examples ofsuitable iron (II) compounds include, but are not limited to, iron (II)sulfate and its hydrates (such as, for example, ferrous sulfateheptahydrate), iron (II) chloride, and iron (II) gluconate. Iron powderin combination with a pH adjusting agent that provides an acidic pH mayalso be used. Other transition metal ions can also be used as thebreaking aid or catalyst, such as manganese (Mn).

Some fluids according to the present application may also include asurfactant. Any surfactant for which its ability to aid the dispersionand/or stabilization of the gas component into the base fluid to form anenergized fluid is readily apparent to those skilled in the art may beused. Viscoelastic surfactants, such as those described in U.S. Pat. No.6,703,352 (Dahayanake et al.) and U.S. Pat. No. 6,482,866 (Dahayanake etal.), both incorporated herein by reference in their entirety, are alsosuitable for use in wellbore fluids.

In some embodiments, the surfactant may be an ionic surfactant. Examplesof suitable ionic surfactants include anionic surfactants such as alkylcarboxylates, alkyl ether carboxylates, alkyl sulfates, alkyl ethersulfates, alkyl sulfonates, α-olefin sulfonates, alkyl ether sulfates,alkyl phosphates and alkyl ether phosphates. Examples of suitable ionicsurfactants also include cationic surfactants such as alkyl amines,alkyl diamines, alkyl ether amines, alkyl quaternary ammonium, dialkylquaternary ammonium and ester quaternary ammonium compounds. Examples ofsuitable ionic surfactants also include surfactants that are usuallyregarded as zwitterionic surfactants, and in some cases as amphotericsurfactants, such as alkyl betaines, alkyl amido betaines, alkylimidazolines, alkyl amine oxides and alkyl quaternary ammoniumcarboxylates. The amphoteric surfactant is a class of surfactant thathas both a positively charged moiety and a negatively charged moietyover a certain pH range (typically slightly acidic), only a negativelycharged moiety over a certain pH range (e.g. typically slightlyalkaline) and only a positively charged moiety at a different pH range(e.g. typically moderately acidic), while a zwitterionic surfactant hasa permanently positively charged moiety in the molecule regardless of pHand a negatively charged moiety at alkaline pH. In some embodiments, thesurfactant is a cationic, zwitterionic or amphoteric surfactantcontaining and amine group or a quaternary ammonium group in itschemical structure (“amine functional surfactant”). A particularlyuseful surfactant is the amphoteric alkyl amine contained in thesurfactant solution AQUAT 944 (available from Baker Petrolite of 12645W. Airport Blvd, Sugar Land, Tex. 77478 USA). In other embodiments, thesurfactant may be a blend of two or more of the surfactants describedabove, or a blend of any of the surfactant or surfactants describedabove with one or more nonionic surfactants. Examples of suitablenonionic surfactants include alkyl alcohol ethoxylates, alkyl phenolethoxylates, alkyl acid ethoxylates, alkyl amine ethoxylates, sorbitanalkanoates and ethoxylated sorbitan alkanoates. Any effective amount ofsurfactant or blend of surfactants may be used in the wellbore fluid.These fluids may incorporate the surfactant or blend of surfactants inan amount of about 0.02 wt % to about 5 wt % of total liquid phaseweight, or from about 0.05 wt % to about 2 wt % of total liquid phaseweight.

Other materials which may be included in a wellbore fluid includeelectrolyte, such as an organic or inorganic salt, friction reducers toassist flow when pumping and surfactants.

A wellbore fluid may be a so-called energized fluid formed by injectinggas (most commonly nitrogen, carbon dioxide or mixture of them) into thewellbore concomitantly with the aqueous solution. Dispersion of the gasinto the base fluid in the form of bubbles increases the viscosity ofsuch fluid and impacts positively its performance, particularly itsability to effectively induce hydraulic fracturing of the formation, andcapacity to carry solids. The presence of the gas also enhances theflowback of the fluid when this is required. In a method of thisapplication the wellbore fluid may serve as a fracturing fluid or gravelpacking fluid and may be used to suspend a particulate material fortransport down wellbore. This material may in particular be a proppantused in hydraulic fracturing or gravel used to form a gravel pack. Themost common material used as proppant or gravel is sand of selected sizebut ceramic particles and a number of other materials are known for thispurpose.

Wellbore fluids in accordance with this application may also be usedwithout suspended proppant in the initial stage of hydraulic fracturing.Further applications of wellbore fluids in accordance with thisapplication are in modifying the permeability of subterraneanformations, and the placing of plugs to achieve zonal isolation and/orprevent fluid loss.

For some applications a fiber component may be included in the treatmentfluid to achieve a variety of properties including improving particlesuspension, and particle transport capabilities, and gas phasestability. Fibers used may be hydrophilic or hydrophobic in nature.Fibers can be any fibrous material, such as, but not necessarily limitedto, natural organic fibers, comminuted plant materials, syntheticpolymer fibers (by non-limiting example polyester, polyaramide,polyamide, novoloid or a novoloid-type polymer), fibrillated syntheticorganic fibers, ceramic fibers, inorganic fibers, metal fibers, metalfilaments, carbon fibers, glass fibers, ceramic fibers, natural polymerfibers, and any mixtures thereof. Particularly useful fibers arepolyester fibers coated to be highly hydrophilic, such as, but notlimited to, DACRON® polyethylene terephthalate (PET) fibers availablefrom Invista Corp., Wichita, Kans., USA, 67220. Other examples of usefulfibers include, but are not limited to, polylactic acid polyesterfibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers,and the like. When used in fluids of the application, the fibercomponent may be present at concentrations from about 1 to about 15grams per liter of the liquid phase, in particular the concentration offibers may be from about 2 to about 12 grams per liter of liquid, andmore particularly from about 2 to about 10 grams per liter of liquid.

Friction reducers may also be incorporated into fluids of theapplication. Any friction reducer may be used. Also, polymers such aspolyacrylamide, polyisobutyl methacrylate, polymethyl methacrylate andpolyisobutylene as well as water-soluble friction reducers such as guargum, guar gum derivatives, polyacrylamide, and polyethylene oxide may beused. Commercial drag reducing chemicals such as those sold by ConocoInc. under the trademark “CDR” as described in U.S. Pat. No. 3,692,676(Culter et al.) or drag reducers such as those sold by Chemlinkdesignated under the trademarks “FLO 1003, 1004, 1005 & 1008” have alsobeen found to be effective. These polymeric species added as frictionreducers or viscosity index improvers may also act as excellent fluidloss additives reducing or even eliminating the need for conventionalfluid loss additives.

Embodiments of the present application may also include proppantparticles that are substantially insoluble in the fluids of theformation. Proppant particles carried by the treatment fluid remain inthe fracture created, thus propping open the fracture when thefracturing pressure is released and the well is put into production.Suitable proppant materials include sand, walnut shells, sinteredbauxite, glass beads, ceramic materials, naturally occurring materials,or similar materials. Mixtures of proppants can be used as well. If sandis used, it will typically be from about 20 to about 100 U.S. StandardMesh in size. With synthetic proppants, mesh sizes about 8 or greatermay be used. Naturally occurring materials may be underived and/orunprocessed naturally occurring materials, as well as materials based onnaturally occurring materials that have been processed and/or derived.Suitable examples of naturally occurring particulate materials for useas proppants include, but are not necessarily limited to: ground orcrushed shells of nuts such as walnut, coconut, pecan, almond, ivorynut, brazil nut, etc.; ground or crushed seed shells (including fruitpits) of seeds of fruits such as plum, olive, peach, cherry and apricot;ground or crushed seed shells of other plants such as various forms ofcorn (corn cobs or corn kernels); processed wood materials such as thosederived from woods such as oak, hickory, walnut, poplar and mahogany,including such woods that have been processed by grinding, chipping, orother form of particalization, processing. Further information on nutsand composition thereof may be found in Encyclopedia of ChemicalTechnology, Edited by Raymond E. Kirk and Donald F. Othmer, ThirdEdition, John Wiley & Sons, Volume 16, pages 248-273 (entitled “Nuts”),Copyright 1981, which is incorporated herein by reference in itsentirety.

The concentration of proppant in the fluid can be any concentrationknown in the art, and may be in the range of from about 0.03 to about 3kilograms of proppant added per liter of liquid phase. Also, any of theproppant particles can be further coated with a resin to potentiallyimprove the strength, clustering ability, and flow back properties ofthe proppant.

The aqueous medium of the present application may be water or brine. Inthose embodiments, the aqueous medium is a brine, the brine is watercomprising an inorganic salt or organic salt. Examples of inorganicsalts include alkali metal halides, such as potassium chloride. Thecarrier brine phase may also comprise an organic salt such as sodium orpotassium formate. Preferred inorganic divalent salts include calciumhalides, such as, for example, calcium chloride or calcium bromide.Sodium bromide, potassium bromide, or cesium bromide may also be used.The salt is chosen for compatibility reasons, this determination may bebased upon the reservoir drilling fluid used a particular brine phaseand the completion/clean up fluid brine phase is chosen to have the samebrine phase.

Fluid embodiments of the present application may further contain otheradditives and chemicals that are known to be commonly used in oilfieldapplications by those skilled in the art. These include, but are notnecessarily limited to, materials such as surfactants in addition tothose mentioned hereinabove, breaker aids in addition to those mentionedhereinabove, oxygen scavengers, alcohols, scale inhibitors, corrosioninhibitors, fluid-loss additives, bactericides, and the like. Also, theymay include a co-surfactant to optimize viscosity or to minimize theformation of stable emulsions that contain components of crude oil orthe hydratable polymer.

Aqueous fluid embodiments of the present application may also comprisean organoamino compound. Examples of suitable organoamino compoundsinclude tetraethylenepentamine, triethylenetetramine,pentaethylenhexamine, triethanolamine, and the like, or any mixturesthereof. When organoamino compounds are used, they may be incorporatedat an amount from about 0.01 wt % to about 2.0 wt % based on totalliquid phase weight. Preferably, when used, the organoamino compound isincorporated at an amount from about 0.05 wt % to about 1.0 wt % basedon total liquid phase weight. A particularly useful organoamino compoundis tetraethylenepentamine.

The well treatment composition may then be introduced or placed in thewellbore or subterranean formation. As used herein, the term“introducing” or “introduced” refers to mechanism of locating the welltreatment composition in the wellbore or subterranean formation byvarious methods and/or with suitable equipment typically used in variousoilfield operations, such as fracturing and cementing. Examples of“introducing” mechanisms include such as, for example, pumping the welltreatment composition through the wellbore or through installedcoiltubing.

The following examples are presented to illustrate the preparation andproperties of aqueous viscoelastic nanotube fluids and should not beconstrued to limit the scope of the application, unless otherwiseexpressly indicated in the appended claims. All percentages,concentrations, ratios, parts, etc. are by weight unless otherwise notedor apparent from the context of their use. The statements made hereinmerely provide information related to the present disclosure and may notconstitute prior art, and may describe some embodiments illustrating theapplication.

EXAMPLES Example 1

The sample was prepared by adding 3 mL borosilicate colloidal dispersioninto 200 mL fully hydrated (Di-water) guar linear gel, under constantmixing in a conventional glass blender cup. The vortex was closed withinabout a minute, which signaled the transformation from a linear polymergel to a crosslinked polymer gel. The pH of the crosslinked polymer gelwas then determined to be 9.1. Then, about a 30 ml volume sample wastransferred to a Couette cup, and assembled onto a M5500 rheometer(GRACE Instrument Company, Houston, Tex.). The sample was covered undera 200 psia nitrogen blanket in the headspace to prevent water fromevaporation at elevated temperatures. The polymer gel went through aprocess of thermal thinning, characteristic to typical crosslinkedfluid, as the rheometer heated up. Subsequently, the polymer gelregained the viscosity when the fluid temperature stabilized. Theviscosity was measured at a constant shear rate of 100/s. As shown inFIG. 1, at a normal concentration level of 5 ppm boron as determined viainductively coupled plasma, the borosilicate colloidal dispersioncrosslinks 30 lbm/1,000 gal US guar. In comparison to conventionalaqueous borate counterpart, it takes less boron to achieve the samelevel of overall viscosity, indicating a more effective crosslinking.Also, it does not require as high pH for crosslinking

Example 2

The sample was prepared by adding 3.8 mL borosilicate colloidaldispersion into 100 mL fully hydrated (Di-water) guar linear gel, underconstant mixing in a conventional glass blender cup. The vortex wasclosed within about a minute, which signaled the transformation from alinear polymer gel to a crosslinked polymer gel. The pH of thecrosslinked polymer gel was then determined to be 9.7. Then, about a 30ml volume sample was transferred to a Couette cup, and assembled onto aM7500 Ultra HTHP rheometer (GRACE Instrument Company, Houston, Tex.).The viscosity was measured at a constant shear rate of 100/s. Aviscosity loss is observed when the static pressure ramps up fromambient to 20,000 psia, but is subsequently regained as a result of thepressure removal. Again, this is a typical pressure effect for boroncrosslinked polymers. But for the borosilicate colloidal crosslinker,the extent of such an adverse effect is significantly reduced comparedto the aqueous borate counterpart. FIG. 2 shows the rheological profileof 12.4 ppm boron in borosilicate colloidal dispersions crosslinking 30lbm/1,000 galUS guar at 120° F.

The foregoing disclosure and description is illustrative and explanatorythereof and it can be readily appreciated by those skilled in the artthat various changes in the size, shape and materials, as well as in thedetails of the illustrated construction or combinations of the elementsdescribed herein can be made without departing from the spirit of thedisclosure.

While the embodiments have been illustrated and described in detail inthe drawings and foregoing description, the same is to be considered asillustrative and not restrictive in character, it being understood thatonly some embodiments have been shown and described and that all changesand modifications that come within the spirit of the applications aredesired to be protected. It should be understood that while the use ofwords such as preferable, preferably, preferred, more preferred orexemplary utilized in the description above indicate that the feature sodescribed may be more desirable or characteristic, nonetheless may notbe necessary and embodiments lacking the same may be contemplated aswithin the scope of the application, the scope being defined by theclaims that follow. In reading the claims, it is intended that whenwords such as “a,” “an,” “at least one,” or “at least one portion” areused there is no intention to limit the claim to only one item unlessspecifically stated to the contrary in the claim. When the language “atleast a portion” and/or “a portion” is used the item can include aportion and/or the entire item unless specifically stated to thecontrary.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this application. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

What is claimed is:
 1. A method of forming a wellbore fluid, the methodcomprising: introducing a polymer; and introducing a crosslinkercomprised of at least a silica material, the crosslinker having adimension of from about 5 nm to about 100 nm.
 2. The method of claim 1,wherein the hydratable polymer is a polysaccharide.
 3. The method ofclaim 1, wherein the hydratable polymer is present in an amount of fromabout 0.05 weight percent to about 10 weight percent.
 4. The method ofclaim 1, wherein the hydratable polymer is selected from the groupconsisting of guar, hydropropyl guar (HPG), carboxymethyl guar (CMG),carboxymethylhydroxypropyl guar, cellulose, hydroxyethylcellulose (HEC),hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose(CMHEC), xanthan, diutan, whelan gum, polyacrylamide, polyacrylatepolymers.
 5. The method of claim 1, wherein the crosslinker comprisesparticles with a dimension of from about 10 nm to about 20 nm.
 6. Themethod of claim 1, wherein the silica material comprises isborosilicate.
 7. The method of claim 6, wherein the content of boron inthe wellbore fluid is between 0.5 and 10 ppm by weight elemental boron.8. The method of claim 6, wherein the wellbore fluid contains not morethan 5 ppm boron for each gram of the hydratable polymer per liter ofthe wellbore fluid.
 9. The method of claim 1, wherein the silica has aconcentration of 20-50 wt % in the crosslinker.
 10. The method of claim1, wherein the crosslinker further comprises zirconium, titanium,aluminum, or a combination thereof. 11.-20. (canceled)
 21. The method ofclaim 1, wherein the polymer is a hydratable polymer.
 22. The method ofclaim 1, wherein an aqueous medium is introduced to the wellbore fluid.23. The method of claim 22, wherein a breaker is introduced to thewellbore fluid.
 24. The method of claim 23, wherein the breaker isencapsulated or in an enclosure.
 25. The method of claim 24, wherein asurfactant is introduced to the wellbore fluid.
 26. The method of claim25, wherein a friction reducer is introduced to the wellbore fluid. 27.The method of claim 26, wherein an organoamino compound is introduced tothe wellbore fluid.
 28. The method of claim 1, wherein a proppant isintroduced to the wellbore fluid.
 29. The method of claim 1, wherein afiber is introduced to the wellbore fluid.
 30. The method of claim 1,wherein a gas is injected into the wellbore fluid.